Systems and methods for shared visualization and display of drilling information

ABSTRACT

A method of visualizing drilling information in a shared visualization environment include receiving a request to initiate a shared visualization session, assigning the requesting client device as the master of the initiated session, and transmitting visualization data to the client device for rendering and display. Additional client devices may join the visualization session and may display the visualization data based on attributes controlled by the master client device. Data displayed in a visualization session may include two- and three-dimensional data representing a composite wellbore derived from actual and planned wellbore data. Generation of the two- and three-dimensional data may include projecting data corresponding to the composite wellbore onto flat and curved planes and may further include supplementing the composite wellbore data with seismic and other drilling-related data.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. application Ser. No.15/343,007 filed Nov. 3, 2016, titled “Automated Geo-Target andGeo-Hazard Notifications for Drilling Systems,” which claims the benefitof priority under 35 U.S.C. § 119(e) to provisional application No.62/250,256 titled “Shared Visualization with Automated Depth Model BasedNotifications for Drilling Systems Utilizing 3D Seismic Data,” filed onNov. 3, 2015, and provisional application No. 62/376,256 titled“Automated Geo-Target and Geo-Hazard Notifications for DrillingSystems,” filed on Aug. 17, 2016, which are hereby incorporated byreference herein. This application further claims priority under 35U.S.C. § 119(e) to provisional application No. 62/367,538 titled “SharedVisualization and Automated Geo-Target and Geo-Hazard Notification forDrilling Systems Utilizing 3D Seismic Data,” filed Jul. 27, 2016, andprovisional application No. 62/376,270 titled “Shared Visualization andAutomated Geo-Target and Geo-Hazard Notifications for Drilling Systems,”filed Aug. 17, 2016, and provisional patent application No. 62/408,585titled “System and Method for Generating and Displaying ThreeDimensional and Two Dimensional Drilling Information,” filed Oct. 14,2016.

TECHNICAL FIELD

The present technology pertains to drilling systems, and morespecifically pertains to shared visualization and display of drillinginformation.

BACKGROUND

An oil company asset team must work to together to ensure the efficientdrilling and completion of an oil and gas well. During the years 2005through 2016, the drilling of horizontal wells in shale formationsbecame a very important new regime of operations for the oil industry.This new regime requires a “factory floor” mindset whereby activitiesbecome repetitive and must be repeatable in order to ensure optimaloutcomes from an economic perspective.

In order to drill a successful horizontal well, a cross-functional team(a.k.a. “asset team”) comprised of engineers, geoscientists, regulatory,financial specialists, managers, and third party service providers, suchas the drilling contractor and mud-logger, must work together. The assetteam must collaborate to plan the well, execute the drilling plan, avoidgeo-hazards, and stay on an optimal drilling track and on the drillingplan. This is challenging since the drilling target geologic horizonwill typically be 2 miles underground and located in a remote fieldarea.

An increasingly important tool for improving the success of thesehorizontal shale drilling projects is 3-dimensional seismic data (3Dseismic). Many oil and gas companies will acquire a 3D seismic surveythat is an image of the subsurface region within which they intend todrill. This seismic survey will be calibrated to existing well controland converted into depth (meaning the z-axis of the seismic volume willreadout in depth below the surface). The target horizon (and potentiallyadditional reference horizons) along which the horizontal well will bedrilled is identified within the seismic volume, along with potentialhazards, which primarily will be geologic faults that intersect thetarget horizon, but which will also include pre-existing wellboreswithin the vicinity. In addition, mineral lease ownership informationcould be included in the depth model. Also, the depth model typicallyincludes a planned drilling wellbore trajectory. This information iscollectively referred to as the “Depth Model.”

As the drilling of the well proceeds, the location of the drill-bitusing measurement while drilling (MWD) information can be transmitted ona periodic (15 minute or other interval), real-time basis to the oilcompany. Not uncommonly, an asset team member (typically a geoscientist)will be assigned to manually update a set of project information on anat least a once daily basis—the project contains the seismic volume, thedepth model including geo-hazards, and the path of the well beingdrilled. This permits the geoscientist to determine whether anexceptional condition is imminent. The geoscientist assigned to thisduty will manually prepare a daily report that includes the seismicimagery, the depth model, and the current well drill bit position, alongwith notes containing an analysis of the exceptional conditions. Thisreport is then distributed manually to the other asset team members tohelp the asset team work together. Regardless, the process is laborintensive, not typically real-time, the information is difficult todistribute and coordinate particularly from remote locations where teammembers are remote from the drilling operations, among numerous otherchallenges and deficiencies.

SUMMARY

Systems and methods for shared visualization of drilling data areprovided. Such systems and methods include receiving, at a server of adrilling management system, a visualization request from a first clientdevice to initiate a shared visualization session of a drilling site.The server, which is communicatively coupled to a data source containingvisualization data for the drilling site, may then assign the firstclient device as a master for the shared visualization session, enablingthe first client device to adjust attributes for viewing thevisualization data of the drilling site. The visualization data is thentransmitted to the first client device which renders the visualizationdata according to the attributes.

A second client device may subsequently request and join thevisualization session as a slave device. As such, the second clientdevice may view the visualization data in accordance with the attributesset by the first client device but is generally unable to modify theattributes. In certain implementations, the second client device mayrequest to be assigned as a temporary master, and, if so assigned, maythen submit commands to modify the attributes governing viewing of thevisualization data by other client devices participating in the sharedvisualization session.

Systems and methods for generating well drilling information are alsoprovided. In such systems and methods, planned wellbore data and actualwellbore data obtained from a drilling data feed are combined togenerate composite wellbore data. The composite wellbore data may thenbe projected onto a three-dimensional well cross section, which is acurved vertical defined along the composite wellbore. Thethree-dimensional well cross section may be supplemented with additionaldata, such as seismic data, indicating geological features or otherpoints of interest and updated in response to receiving new data from adrilling data feed.

In certain implementations, a two-dimensional well vertical section mayalso be generated by projecting the composite wellbore data onto atwo-dimensional plane defined between an origin of the planned wellboreand a specified azimuth. Additional information, such as intersectionsbetween the composite wellbore and geological features, may also beprojected onto the well vertical section. The vertical well section andthe three-dimensional well cross section may be displayed using a twodimensionally referenced user interface and three dimensionallyreferenced user interface, respectively. In certain implementations, auser may be able to switch between such interfaces and correspondingviews of the composite wellbore data.

Additional features and advantages of the disclosure will be set forthin the description which follows, and in part will be obvious from thedescription, or can be learned by practice of the herein disclosedprinciples. The features and advantages of the disclosure can berealized and obtained by means of the instruments and combinationsparticularly pointed out in the appended claims. These and otherfeatures of the disclosure will become more fully apparent from thefollowing description and appended claims, or can be learned by thepractice of the principles set forth herein.

BRIEF DESCRIPTION OF THE DRAWINGS

The above-recited and other advantages and features of the disclosurewill become apparent by reference to specific embodiments thereof whichare illustrated in the appended drawings. Understanding that thesedrawings depict only exemplary embodiments of the disclosure and are nottherefore to be considered to be limiting of its scope, the principlesherein are described and explained with additional specificity anddetail through the use of the accompanying drawings in which:

FIG. 1 illustrates an exemplary system for automated geo-target andgeo-hazard notifications for drilling systems;

FIG. 2 illustrates an exemplary system embodiment of a drillingmanagement system;

FIG. 3 illustrates an example method of automated geo-target andgeo-hazard notifications for drilling systems; and

FIGS. 4A-4D illustrate exemplary visualizations of an active drill;

FIG. 5 illustrates an example method of initiating a sharedvisualization between users of a drilling management system;

FIG. 6 illustrates an example method of joining a client device with apreviously initiated shared visualization session;

FIG. 7 illustrates an example method of adjusting viewing attributes ofa shared visualization session;

FIG. 8 illustrates an example method of temporarily assigning a clientto device as a master of an initiated visualization session;

FIG. 9 illustrates a drilling plan;

FIG. 10 illustrates an isometric view of the drilling plan of FIG. 9including a three-dimensional well cross section;

FIG. 11 illustrates a vertical section of the drilling plan of FIG. 9;

FIG. 12 illustrates a method of generating and displaying drillinginformation corresponding to a composite wellbore;

FIG. 13 illustrates a method of supplementing and displaying compositewellbore data with geological feature data;

FIG. 14 illustrates a method of generating and displaying a verticalsection of a well bore; and

FIGS. 15A and 15B illustrate exemplary possible system embodiments.

DESCRIPTION

Various embodiments of the disclosure are discussed in detail below.While specific implementations are discussed, it should be understoodthat this is done for illustration purposes only. A person skilled inthe relevant art will recognize that other components and configurationsmay be used without parting from the spirit and scope of the disclosure.

The disclosed technology addresses the need in the art for automatedgeo-target and geo-hazard notifications for drilling systems. A drillingmanagement system can monitor the traversed path of a drill bitthroughout active drilling at a drilling site and notify appropriateteam members regarding a current status of the active drilling inreal-time. As used herein, the term real-time recognizes that there arevarious steps and operations that must occur prior to the systemreceiving information about the location of the wellbore, and the systemmay be configured to monitor the system based on the most current drillbit information but may be configured to provide notifications on someschedule. For example, some time may pass between transmission of drillbit information from the well to the system and hence the term real-timerecognizes some time may pass between when the drill bit reaches somelocation and when the system obtains the information as to the currentlocation of the drill bit, and hence the term real-time captures nearreal-time values (e.g., while drilling and within 10 minutes of thedrill bit reaching some point in the drilling operation). With respectto notification, for example, the drilling management system can notifyteam members when predetermined milestones have been met, when the drillbit is drifting off course from a target wellbore trajectory and/ortarget horizon, or when the drill bit is in danger of running into ageo-hazard, such as a pre-existing wellbore, unpierced fault plane,lease boundary, etc. The drilling management system can maintain a depthmodel of the drilling site that identifies the target wellboretrajectory and coordinates of known geo-hazards at the drilling sites.The drilling management system can also maintain a set of rules for eachof the drilling sites that indicate when team members should benotified.

While an active drill is in progress at a drilling site, the drillingmanagement system can receive a drilling data stream (e.g., a stream ofdata generated from MWD data captured from an MWD tool) from thedrilling site that includes coordinate data describing a traversed pathof a drill bit. The drilling management system can determine, based onthe coordinate data and the depth model of the drilling site, whether arule has been triggered indicating that one or more team members shouldbe notified regarding the status of the active drill. In response todetermining that the rule has been triggered, the drilling managementsystem can identify a set of team members that should be notified, andtransmit a notification to the team members that the rule has beentriggered.

The disclosed technology further provides enhanced capabilities forcollaboration between asset team members. In a first aspect, systems andmethods for shared visualization of drilling information is provided.The systems and methods enable asset team members operating various ofclient devices to access and view drilling information accessible to thedrilling management system. Client devices may access the drillinginformation through a web browser or similar application which obtainsand renders the data for viewing by a user of the respective clientdevice. Users are also able to participate in shared visualizationsessions with other asset team members. During such shared visualizationsessions, one client device may be designated as a master client deviceand, as the master client device, may be able to control the viewingattributes of all client devices in participating in the sharedvisualization session.

In another aspect of the present disclosure, a method of generating andpresenting drilling information in various formats is provided. Themethod includes generating composite wellbore data for a given well bycombining actual wellbore data obtained during drilling of the well withplanned wellbore data for any portion of the well yet to be drilled. Thecomposite wellbore data may then be projected onto a 3D well crosssection or a vertical section and displayed through a 3D or 2D userinterface, respectively. The displayed data may also include additionalinformation including geological formation data, seismic image data, andpoints of interest identified by users. Users may also readily changebetween 3D and 2D representations of the wellbore data to facilitatecommunication and understanding between asset team members thatconventionally interpret well data in 3D (such as geoscientists) andthose that conventionally work with 2D representations (such as drillingengineers and technicians).

FIG. 1 illustrates an exemplary system for automated geo-target andgeo-hazard notifications for drilling systems. As illustrated, multiplecomputing devices can be connected to a communication network 104 and beconfigured to communicate with each other through use of thecommunication network 104. The communication network 104 can be any typeof network, including a local area network (“LAN”), such as an intranet,a wide area network (“WAN”), such as the Internet, or any combinationthereof. Further, the communication network 104 can be a public network,a private network, or a combination thereof. The communication network104 can also be implemented using any number of communication linksassociated with one or more service providers, including one or morewired communication links, one or more wireless communication links, orany combination thereof, and may support the transmission of dataformatted using any number of protocols, as well as different protocolsas data traverses the various paths between devices.

A computing device, which may be involved in obtaining and transmittingdrilling information, the drilling management system, and the clientdevices, can be any type of general computing device capable of networkcommunication with other computing devices. For example, a computingdevice can be a personal computing device such as a desktop orworkstation, a business server, or a portable computing device, such asa laptop, smart phone, or a tablet PC. A computing device can includesome or all of the features, components, and peripherals of computingdevice 500 of FIGS. 5A and 5B.

To facilitate communication with other computing devices, a computingdevice can also include a communication interface configured to receivea communication, such as a request, data, etc., from another computingdevice in network communication with the computing device and pass thecommunication along to an appropriate module running on the computingdevice. The communication interface can also be configured to send acommunication to another computing device in network communication withthe computing device.

As shown, the overall system 100 includes a drilling management system102, drilling sites 106(1), 106(2), . . . , 106(N) (collectively “106”),and more particularly computing devices at subsites and client devices108(1), 108(2), . . . , 108(N) (collectively “108”). The drillingmanagement system 102 can be comprised of one or more computing devicesconfigured to monitor the traversed path of a drill bit throughoutactive drilling at any drilling sites 106, through receiving drillinginformation (e.g., MWD of the based information), and communicate withvarious client devices 108 to notify associated team members regardingthe status of active drilling at the drilling sites 106 in real-time.

The drilling sites 106 can be physical drilling sites equipped withdrilling machinery, and accompanying sensors and computing devices, suchas an MWD component associated with a drill bit, configured to gatherdrilling data describing the status of an active drilling operation at adrilling site 106. For example, the drilling data, in the form of MWDdata, may be delivered in the form of sets of Azimuth (inclination fromNorth), Inclination (dip in degrees), and MD (measured length alongwellbore). The data may be converted to x, y, z axis values using anyindustry standard conversion. The conversion may occur prior to thedrilling data transmitting (e.g., the drilling stream) to the drillingmanagement system. Hence, the drilling data can include coordinate data,such as an x-axis value, y-axis value and z-axis value, describing thelocation of a drill bit as the drill traverses through the ground duringthe active drill. Systems at the drilling sites 106 can gather andtransmit this drilling data to drilling management system 102 as part ofa drilling data stream. For example, drilling sites 106 can gather andtransmit drilling data to drilling management system 102 every 10seconds, 30 second, 1 minute, 5 minutes, etc. In one specific example,MWD drill bit positional data is collected by an MWD tool associatedwith the drill string and typically positioned behind the drill bit. Asintroduced above, the MWD tool measures Azimuth, Inclination, and lengthalong the well drilling string in real-time. The tool transmits the datato the surface using “mud pulses”—digital pulses sent through drillingfluid, in the wellbore, to the surface where the pulses are encoded withpositional data as well as other information. A transducer at thesurface converts these pulses back into digital information on a networkon the drilling rig. The MWD data may be then be translated to x, y, andz values at a local computing device and transmitted, such as form aprivate web server at the drilling site, to the drilling managementsystem using the WITSML protocol.

In addition to coordinate data describing the location of a drill bit,drilling data can also include additional data describing an activedrill. For example, the drilling data can include identifying data, suchas a unique identifier identifying the originating drilling site 106,identifiers of equipment used for drilling, such as the drill bit,sensors, computing devices, etc. The drilling data can also include timestamp values indicating the time at which coordinate values for anactive drill were recorded. Drilling data can also include other sensorreadings or data gathered during the active drill, such as sensorreadings describing traversed soil densities, drill bit pressures, drillbit performance, etc. The drilling data may also include logging whiledrilling (LWD) data including Gamma Ray Log information. The Gamma Raylog records the intensity of naturally occurring gamma radiation fromrock.

The drilling management system 102 can receive drilling data streamsfrom one or more of the drilling sites 106 and analyze the drilling datato determine whether team members associated with the active drillshould be notified regarding the status of the active drill. Forexample, the drilling management system 102 can notify team members whenpredetermined milestones have been met, when the drill bit is driftingoff course from a target wellbore trajectory or when the drill bit is indanger of running into a geo-hazard, such as a pre-existing wellbore,unpierced fault plane, lease boundary, etc.

To accomplish this, the drilling management system 102 can access adepth model for the area being drilled at each drilling site 106, thedepth model may identify the target wellbore trajectory for the drillingsite 106, coordinates of known geo-hazards. Generally speaking, thedepth model is derived from the seismic data for the area to be drilledat the drilling site. Typically, seismic interpretation programs areused to digitize x, y, z coordinate data for a set of seismic data. Thedigitized coordinates represent and constitute a 3D dimensional surface.Likewise, features identified within the seismic data may be digitizedinto unique three dimensional surfaces to form part of the depth model.For example, geologic faults, hazards, target horizons or boundaries andthe like may be digitized into three dimensional surfaces representativeof the respective features. Each data type (the seismic data and thederived horizon and fault surfaces) and the well data (the MWD and LWDinformation) has its own elevation datum). To align the various datasets used for comparison purposes and to trigger notifications, and thelike, the elevation datum may be reconciled if necessary. For example,if the seismic data used to generate the seismic cube has a datumelevation of 5200 ft above sea level, and the drilling data has a datumelevation of 5250 feet above sea level, the depths between the two setsof data can be reconciled by adding 50 ft to the seismic data. The depthmodel may be based on seismic data for the area being drilled, and maybe arranged in a cube with x (e.g., inline), y (e.g., crossline) and/orz (e.g., time or depth) aspects of the cube.

The drilling management system 102 can also maintain a set of rules foreach drilling site 106 that indicates when team members for the drillingsite 106 should be notified regarding the status of the active drill.For example, the rules can identify milestones that, when met, should bereported to specified team members. As another example, the rules canidentify threshold distances from the target wellbore trajectory, thetarget horizons, and/or geo-hazards that, when met or exceeded, arereported to a specified team member or members. The drilling managementsystem 102 can use the drilling data received from a drilling site 106,along with the corresponding depth model and set of rules, to determinewhen a rule has been triggered and team members should be notifiedregarding the status of the active drilling operation.

The drilling management system 102 can notify team members via clientdevices 108. Client devices 108 can be any type of computing devices,such as a smart phones, laptop computers, desktop computers, tablets,etc. Drilling management system 102 can maintain records of clientdevices 108 associated with team members, including contact informationto reach team members via one or more of client devices 108. In responseto determining that a team member should be notified, drillingmanagement system 102 can identify the team members contact informationand transmit a notification to the user, which can be received by theuser at one or more of client devices 108. For example, drillingmanagement system 102 can transmit the notification as an e-mail, textmessage, phone call, instant message, etc.

Drilling management system 102 can also provide team members with avisualization of an active drill. For example, drilling managementsystem 102 may use techniques such as those described in U.S. Pat. No.9,182,913 (the “'913 Patent”) titled “Apparatus, System an Method forthe Efficient Storage and Retrieval of 3-Dimensionally Organized Data inCloud Based Computing Architectures,” which is hereby incorporated byreference, to among other things, store, access, and view 3D seismicdata and depth models within a cloud architecture utilizing a webbrowser or other client side application. The method disclosed in the'913 Patent also provides for the efficient access to the depth modelover network connections.

Team members can use client devices 108 to communicate with drillingmanagement system 102 to request a visualization of an active drill. Inresponse, drilling management system 102 can transmit visualization datato the team member's client device 108. The visualization data can berendered by client device 108, for example in a web browser or otherclient-side application, to present the user with a visualization of anactive drill. This can include a 2 or 3 dimensional rendering of thedrilling site including a visual representation of the traversed path ofthe drill bit, the target wellbore trajectory, target horizon, andgeo-hazard, such as a pre-existing wellbores, unpierced fault planes,lease boundaries, etc.

FIG. 2 illustrates an exemplary system embodiment of a drillingmanagement system 102. FIG. 2 is described in view of the system andcomponents described in FIG. 1. As shown, the drilling management system102 includes a data stream receiving module 202, a rule analysis module204, a notification module 206, a data visualization module 208, a datastream storage 210, a depth model storage 212 and a rules storage 214.The various modules may involve a processor (or processors) and computerexecutable instructions to receive the data stream, apply one or morerules to the data stream, and provide notifications as needed. Thestorage may be provided by one or more tangible readable media, providedas a database or databases, where data from the data stream is stored,the depth model is stored, and rules are stored.

The data stream receiving module 202 receives drilling data streams fromone or more drilling sites 106. A drilling data stream can includedrilling data describing an active drill. In one possible example, thedata stream is accessed from a server or other computing device at therespective well and may be formatted according to the WellsiteInformation Transfer Standard Markup Language (WITSML) standard. Thedata stream may be received at the drilling management system and/or thedata stream storage over the network 104. The data stream receivingmodule 202 can receive and store the received drilling data in the datastream storage 210. The data stream storage 210 can include a datastream index for one or more of the drilling sites 106. The drillingindex can be a data index, data file, database, data table, etc., thatincludes a listing of drilling data received from a particular drillingsite 106. For example, a drilling index can include a listing ofcoordinate data describing the location of a drill bit at the drillingsite 106, as well as time stamp data, identifying data, etc. As adrilling operation procedure, the data stream will provide updated dataas to the progress of the drilling operation and the current location ofthe drill bit. Accordingly, the drilling index for a drilling site 106can include data documenting the traversed path of the drill bit at thedrilling site 106, as well as other sensor data and metadata describingdrilling at the drilling site 106.

Each drilling index can be associated with a unique identifieridentifying the corresponding originating drilling site 106. The datastream receiving module 202 can identify the unique identifier includedin a received drilling data stream to identify the correspondingdrilling index in data stream storage 210 and record the receiveddrilling data in the identified drilling index.

The rule analysis module 204 is configured to analyze received drillingdata to determine whether to notify team members regarding the status ofan active drill. For example, the rule analysis module 204 can utilizethe drilling data along with a depth model and a set of rulescorresponding to a drilling site 106 to determine whether a rule hasbeen triggered and team members should be notified.

The depth model storage 212 can store depth models for drilling sites106 and rule storage 214 can store sets of rules for the drilling sites106—with rules being unique and/or common to each drilling site. Eachdepth model and set of rules can be associated with a unique identifierfor its corresponding drilling site 106. The rule analysis module 204utilizes the unique identifier for a drilling site 106 to gather thecorresponding drilling index, depth model and set of rules from datastream storage 210, depth model storage 212 and rule storage 214,respectively.

The rule analysis module 204 can then use the gathered data to determinewhether a rule has been triggered. Moreover, the rule analysis module204 can determine whether a rule has been triggered according to apredetermined temporal schedule, such as every 5 seconds, 10 seconds, 1minute, etc. The rule analysis module 204 can also determine whether arule has been triggered as updated coordinate data (e.g., relative drillbit location data) is received from a drilling site 106 as part of adrilling data stream.

The set of rules for a drilling site 106 can include any number or typeof rules and/or conditions for notifying team members. For example, aset of rules may include a simple temporal milestone rule dictating thatteam members be notified of the status of an active drill at specifiedtime intervals, such as every 30 seconds, 1 minute, 5 minutes, etc., oraccording to a specified time schedule. In one example, a user interface(UI) may be accessed through a client service log, where the UI providesaccess to a set of preconfigured rules. The UI may include fields toactivate any given rule well or to set variable for any given rule. Theupdate time may be a variable set through the UI. The rule analysismodule 204 can monitor elapsed time during an active drill for eachspecified temporal milestone.

As another example, a set of rules can include a distance basedmilestone rule dictating that team members be notified as the drill bitreaches predetermined distance intervals (a variable setable through theUI), such as every 10 feet, 20 feet, 100 feet etc., or according to aspecified distance schedule. The rule analysis module 204 can utilizethe location data stored in the drilling index to determine the currentlocation of a drill bit as well as the distance traversed by the drillbit during the active drill and determine whether the rule has beentriggered.

As another example, a set of rules can include a trajectory deviationrule dictating that team members be notified when the current locationof the drill bit deviates beyond a predetermined threshold distance fromthe target wellbore trajectory and/or the target horizon for the drillbit. Rule analysis module 204 can utilize the location data stored inthe drilling index to determine the current location of a drill bit andutilize the depth model to determine the target wellbore trajectoryand/or the target horizon. Rule analysis module 204 can then determinethe distance between the current location of the drill bit and thetarget wellbore trajectory and/or target horizon and compare thedistance to a threshold distance to determine whether the rule has beentriggered.

With respect to the comparing the actual drill bit location to thedrilling plan, a distance is computed between a point inthree-dimensional space (the x, y, z coordinate for the current locationof the drill bit) and the drilling plan, which may be represented by apolyline in three dimensional space (series of points through the 3Dspace of the depth model). The distance may be resolved into az-component and an xy-component that is projected onto the well planvertical plan, which may be defined in the depth model or separatetherefrom. In that regard, the system can determine the location of thedrill bit relative to plan and provide any suitable notification—e.g.,“at 5:30 p.m., the drill bit is 15 feet above the drilling plan, and 10feet North of the drilling plan”.

As another example, a set of rules can include a trajectory deviationrule dictating that team members be notified when an angle of the drillbit relative to the target horizon exceeds a threshold angle deviationfrom the target horizon. Rule analysis module 204 can utilize thelocation data stored in the drilling index to determine a direction(i.e., vector direction) of the drill bit and utilize access the targethorizon from the depth model. Rule analysis module 204 can thendetermine an angle deviation of the drill bit from the target horizonand compare the angle deviation to the threshold angle deviation todetermine whether the rule has been triggered.

As another example, a set of rules can include a minimum distance ruleto a geo-hazard, such as a pre-existing wellbore, unpierced fault planeor lease boundary. Rule analysis module 204 can utilize the locationdata stored in the drilling index to determine the current location of adrill bit and utilize the depth model to determine the location of ageo-hazard. Rule analysis module 204 can then determine the distancebetween the current location of the drill bit and the geo-hazard andcompare the distance to a threshold distance to determine whether therule has been triggered. In this example, the computed X, Y, Z positionof the drill bit (current and the previous values, which trace out theactual wellbore path) are compared to the location of a fault surface.The fault surface is stored as a triangulated surface in the same X, Y,Z coordinate system as the coordinates of the path of the drill bit.Computational geometry is used to compute the distance between a pointin 3D space (e.g., the most recent position of the drill bit) and asurface in 3D space along a direction vector (the direction that thedrill bit is heading). The distance is expressed in standard distanceunits (meters). So, if a threshold distance has been set for proximityto fault surfaces (such as 50 meters, which may be a variable), whenthat distance is less than or equal to 50, a notification is generated.

With respect to the intersection of the drill bit with a geo-hazard ofsome sort, the planned wellbore (a polyline in 3D space) indicatesapproximately where the wellbore is going to be, and the actual wellboreindicates the real-time (near real-time position) of the drill bit. Inone example, any fault surface that intersects the planned wellbore maybe considered a “geo-hazard”. For any such fault surface, the system cancompute the distance to the geo-hazard by computing the distance fromthe current drill bit position to the intersection of the plannedwellbore with that fault surface. Furthermore, the system can estimatethe time of the intersection occurring by dividing the distance by thecurrent Rate of Penetration of the drilling (expressed by convention asFeet or Meters per Hour), which may be received by the system with thedrilling information provided by the MWD system.

Rule analysis module 204 can determined the distance between the currentlocation of the drill bit and another location based on geographiccoordinates associated with the two points, such as an x coordinatevalue, y coordinate value and z coordinate value assigned to drill bitand the other point. In instances where an object is associated withmultiple geographic coordinates, such as a target wellbore trajectory,lease boundary, pre-existing wellbore, etc., rule analysis module 204can determine the shortest distance between the current location of thedrill bit and the other location.

In another example, the rule analysis module may compare the currentdrill bit position to a target horizon or target horizons. The ruleanalysis module may also compare the drill bit to a range of distancesfrom a target horizon, or may generate a virtual horizon and compare thelocation of the drill bit to the virtual horizon. In one example, thedepth model may include at least one target horizon. The target horizon,may be a surface comprised of x, y, and z coordinate data. The targethorizon may be associated with the top surface, bottom surface or someother surface associated with a formation identified in the seismic datacube from which the depth model is based. For example, a shale bearingformation may be identified in a seismic data set, and a target horizonmay be generated and stored for a surface representing the top surfaceof the formation.

Continuing with the example of a shale formation and a horizon defininga surface in the depth model for the top of the formation, duringdrilling, it may be desired to drill a horizontal well within somedistance from the top of the formation. Hence, a rule may be created tocompare the current drill bit position with a target horizon, andgenerate some form of notification when the drill bit deviates somedistance, defined in the rule, from the top of the formation. In anotherexample, it is possible to define a second horizon, such as related tothe bottom of the shale formation, and define a rule that provides anotification when the drill bit comes within some target distance ofeither the top or the bottom of the formation.

In yet another example, the system (e.g., the rule module) may generatea virtual horizon. In one example, the virtual horizon may be a surfacedefined as some set distance from another surface, such as a virtualhorizon defined relative to a target horizon in the depth model. Therule may both generate the virtual horizon, and be defined to generate anotification based on the distance of the drill bit from the virtualhorizon. In this example, the target horizon is a surface within thedepth model, where the surface is based on some corresponding feature inthe related seismic data, and the virtual surface is a surface that isgenerated based on some mathematical relationship to the target horizon.A virtual surface may be useful, for example, when the resolution of theseismic data is insufficient to identify sub features within aformation, but it is believed, based on perhaps other information, thatit is useful to target or avoid the sub feature and a virtual surface isgenerated for the sub feature, and the rule then based on the subfeature.

The notification module 206 is configured to notify team members when arule has been triggered. Rule analysis module 204 can provide to thenotification module 206, when a rule has been triggered, the dataidentifying the triggered rule. In one example, the UI may include afunction for team member contact information is entered. The contactinformation may include a phone number for an SMS message, an emailaddress, or other information for the form of communication. The teammembers and contact information may be linked to the drilling site, andwhenever a rule is triggered for the drilling site, the team receives amessage over the form (or forms) of communication entered in the site.

In response to receiving a notification from the rule analysis module204 that a rule has been triggered, notification module 206 can identifya set of team members that should be notified. In some embodiments, eachrule can identify the corresponding team members that should be notifiedwhen the rule has been triggered as well as include contact informationfor the identified team members, preferred contact method for the teammembers and/or data that should be provided to the team members.Notification module 206 can use the data in the triggered rule togenerate and transmit notification messages to the team members. Forexample, notification module 204 can transmit the notification messagesas text messages, instant messages, e-mails, etc.

Data visualization module 208 can be configured to provide team memberswith a visualization of an active drill. The visualization of the activedrill can be a two- or three-dimensional rendering of the active drillat a drill site 106, including a visual representation of the traversedpath of the drill bit, the target wellbore trajectory, target horizon,and geo-hazard, such as a pre-existing wellbores, unpierced faultplanes, lease boundaries, etc.

Data visualization module 208 can receive data visualization requestsfrom client devices 108 for a visualization of an active drill. A datavisualization request can include data identifying a drilling site 106,such as the unique identifier for the drilling site 106. Datavisualization module 208 can use the unique identifier included in thevisualization request to identify and gather the corresponding drillingindex in data stream storage 210 and depth module in depth model storage212. Data visualization module 208 can use the gathered data to generatevisualization data that can be rendered by client devices 108 to presentthe visualization of the active drill. Data visualization module 208 canprovide the generated visualization data to the requesting client device108, where it can be rendered for the team member. Data visualizationmodule 208 can continue to provide updated visualization data to clientdevice 108 to update the visualization of the active drill, therebyallowing the team member to view progress of the active drill inreal-time.

FIG. 3 illustrates an example method 300 of automated geo-target andgeo-hazard notifications for drilling systems. It should be understoodthat there can be additional, fewer, or alternative steps performed insimilar or alternative orders, or in parallel, within the scope of thevarious embodiments unless otherwise stated.

At step 302, a drilling management system can receive a first drillingdata stream. The first drilling data stream can include coordinate datadescribing a traversed path of a drill while drilling a well at a firstdrilling site. For example, the coordinate data can include an X axisvalue, a Y axis value and a Z axis value of the drill. The Z axis valuecan indicate a depth of the drill.

At step 304, the drilling management system can determine, based on thecoordinate data and a depth model of the first drilling site, that afirst rule has been triggered. The depth model of the first drillingsite can identify a target wellbore trajectory for the drill at thefirst drilling site. For example, the drilling management system candetermine, based on the coordinate data, a current location of the drilland a distance between the current location of the drill and the targetwellbore trajectory. The drilling management system can then determinethat the distance between the current location and the target wellboretrajectory meets or exceeds a threshold distance dictated by the firstrule.

At step 306, the drilling management system can identify at least afirst user that should be identified when the first rule has beentriggered. For example, the first rule can include data identifying theat least a first user that should be identified when the first rule hasbeen triggered.

At step 308, the drilling management system can transmit a notificationto the first user that the first rule has been triggered.

FIGS. 4A-4D illustrate exemplary visualizations of an active drill alongwith various possible information used by the rule module to generate anotification. The visualization of the active drilling operationdepicted in FIG. 4A presents a 3 dimensional representation of a drillsite 400 (e.g., 3d seismic volume) including a target horizon 402 andseismic cross-section 404. The intersection of the target horizon andthe seismic cross-section represents a target wellbore trajectory 406 ofthe drill bit. The current location of the drill bit 408 (as obtainedfrom the drill stream data) as well as the traversed path 410 of thedrill bit (e.g., wellbore path) is presented relative to the 3d seismicvolume, thereby allowing a team member to visually determine whether thedrill bit is remaining on the target wellbore trajectory.

FIG. 4B shows another visualization of an active drill. As show by thedrill bit path 410, the drill bit 408 has drifted away from the targetwellbore trajectory 406. As mentioned above, the system may provide thevisualization through a web browser. Within the browser, an alert (aform of notification) may be posted and a visual cue 412 provided in theviewable seismic cube. For example, a deviation alert in the form of atext box may pop up in the browser window, and a color coded portion ofthe actual drill path relative to the target trajectory highlighted insome form such as a different color relative to the non-deviated portionof the drill path.

FIG. 4C shows another visualization of an active drill. As shown, thelocation of a pre-existing wellbore 414 is presented in addition to thetraversed path 410 of the drill bit 408 and the target wellboretrajectory 406. Additionally, a minimum threshold distance that thedrill must maintain from the pre-existing wellbore is represented as acylinder 416 surrounding the pre-existing wellbore. The cylinder may berepresented in the depth model as a three dimensional surface derivedfrom a radius, of whatever distance needed, around the pre-existingwellbore. For example, a cylindrical x, y, z surface may be generatedaround the wellbore based on a 50 foot radius. Hence, an alert will betriggered when the current drill bit position intersects any data pointof the cylinder defined by the 50 foot radius (e.g., the drill bit getswithin 50 feet of a pre-existing wellbore). A team member can view thisvisualization and easily determine that the drill bit has drifted awayfrom the target wellbore trajectory and is approaching the minimumthreshold distance from the pre-existing wellbore.

FIG. 4D shows another visualization of an active drill. As shown, thelocation of a geologic fault surface 418 is show in relation to thetraversed path 410 of the drill bit. A team member can view thisvisualization and easily determine that the drill bit is nearing thegeographical fault surface, and a rule may trigger an alert or othernotification where the drill bit 408 reaches some distance from thefault. In this example, the geo-hazard 418 may also be color coded foreasy differentiation relative to other features.

Shared Visualization of Drilling Information

Drilling operations are a collaborative effort involving multiplemembers of an asset team. In such work environments, the accurate andefficient sharing of data between members of the asset team may becritical to the overall success and efficiency of a particular project.Accordingly, systems and methods in accordance with the presentdisclosure enable a collaborative working environment in which drillinginformation is presented through a visualization environmentsimultaneously accessible by multiple client devices.

With reference to the system 100 of FIG. 1 and the drilling managementsystem 102 of FIGS. 1 and 2, one of the client devices 108, for exampleclient device 108(1) transmits a request to the drilling managementsystem 102, such as through a web browser or other application, toinitiate a shared visualization session. The shared visualizationsession is then initiated with the requesting client device 108(1) beingassigned as the master for the session. Other client devices 108 maythen join the visualization session, again through a browser or otherapplication, as “slave” devices. Each of the client devices 108subsequently receives and displays drilling information from thedrilling management system 102. The master client device 108(1) may beused to make adjustments to visualization attributes (such as zoomlevels, angles of viewing, etc.) that are then forwarded to the otherclient devices such that the master client device 108(1) may directviewing and presentation of the drilling information. In certainimplementations, the drilling management system 102 may also allow themaster client device 108(1) to temporarily relinquish the master statusto one or more of the other client devices 108. The client device towhich the master status is relinquished may then be used to modify thevisualization attributes.

FIG. 5 illustrates an example method 500 of initiating a sharedvisualization session. It should be understood that there can beadditional, fewer, or alternative steps performed in similar oralternative orders, or in parallel, within the scope of the variousembodiments unless otherwise stated. The following discussions of FIG.5-8 make additional reference to the system 100 and drilling managementsystem 102 of FIGS. 1 and 2. Such references are intended only toprovide context to the following descriptions of the methods illustratedin FIGS. 5-8.

At step 502, a drilling management system 102 can receive avisualization request from a client device, such as client device108(1), to initiate a shared visualization session of a drilling site.The visualization request can be transmitted as a result of a request toinitiate the visualization session using a web browser of other clientside application on the client device 108(1).

At step 504, the drilling management system 102 can initiate the sharedvisualization session of the drilling site. Because the client device108(1) requested to initiate the shared visualization session, theclient device 108(1) is assigned as a master for the sharedvisualization session and is enabled to adjust attributes for defining aview of the drilling site during the shared visualization session. Thedrilling management system 102 can mark the initiated sharedvisualization session with a unique identifier associated with theclient device 108(1) to designate that the client device 108(1) isassigned as the master. To initiate the shared visualization session,the drilling management system 102 can initiate a direct communicationsession with the client device 108(1) using a designated web-socket ofthe drilling management system 102. The direct communication session canbe maintained for the duration of the shared visualization session.

At step 506, the drilling management system 102 can transmit, to theclient device 108(1), visualization data for the drilling site.Transmitting the visualization data to the client device 108(1) cancause the client device 108(1) to render the visualization data of thedrilling site according to a set of attributes defining a view of thedrilling site. The attributes can include any type of attribute such asrotation angles, zoom level, designated visibilities, colors of objects,cursor position, whether to view in 3D or 2D, etc. Once thevisualization session has been initiated, additional users of otherclient devices, such as client devices 108(2)-108(N), can join theshared visualization session as “slave” devices that have limitedcapabilities with respect to the visualization session. For example, incertain implementations, slave devices are restricted from adjustingattributes for defining a view of the drilling site during the sharedvisualization session.

FIG. 6 illustrates an example method 600 of adding an additional user toan initiated shared visualization session. It should be understood thatthere can be additional, fewer, or alternative steps performed insimilar or alternative orders, or in parallel, within the scope of thevarious embodiments unless otherwise stated.

As illustrated in FIG. 1, the system 100 may include a plurality ofclient devices 108. Each of the client devices, regardless of whether itis designated as a master or slave device, may be capable oftransmitting commands to the drilling management system 102 or otherclient devices 108. To facilitate communication of such commands, eachclient device 108 may be assigned a unique identifier that may beincluded with or appended to commands transmitted from the clientdevices 108. Such identifiers may be used to indicate the source of acommand and/or the intended recipient of a command. In certainimplementations, commands issued by any of the client devices 108 in theshared visualization session may be transmitted as multicast messages,meaning that the message is sent to and received by each client device108 participating in the shared visualization session. In certainimplementations, for example, commands are first sent to the drillingmanagement system 102 which then forwards the commands to each of theother client devices 108 included in the shared visualization session.The client devices 108 may then decide whether to accept or ignorecommands based on, among other things, whether their respective uniqueidentifier is included in the command. Each command may includeadditional data, such as a command type or name, attribute information,the unique ID of the command sender, etc.

At step 602, the drilling management system 102 receives, from arequesting client device, such as the client device 108(2), a request tojoin a previously initiated shared visualization session of a drillingsite. For example, in certain implementations, the client device 108(2)requests to join an initiated shared visualization session by sending a“catch up” command to the drilling management system 102.

The “catch up” command functions as a request for the current attributesdefining the view of the master client device (e.g., the client device108(1)). The catch up command may be required in implementations inwhich attributes defining the view of the master client device 108(1)are only transmitted periodically or when a change is made by the masterclient device 108(1). In such implementations, a client device joining ashared visualization session may not have the same view attributes asthe master client device 108(1) and may not be properly updated until anew set of attributes is provided by the drilling management system 102.Accordingly, the catch up command enables a client device joining aninitiated visualization session to have its view attributes synchronizedwith those of the master client device 108(1) and any other clientdevices 108 in the initiated visualization session.

At step 604, the drilling management system 102 transmits, to the masterclient 108(1), a catch up request indicating that the requesting clientdevice 108(2) has requested to join the shared visualization session. Asexplained above, the catch up request is transmitted as a multicastmessage and will be received by each client device 108 participating inthe shared visualization session. While the catch up request will betransmitted to each participating client device 108, it will only beanswered by the client device assigned as the master and ignored by theothers.

At step 606, the drilling management system 102 receives, from themaster client device 108(1), a catch up response including a set ofattributes defining the view state of the master client device 108(1)and the unique identifier of the requesting client device 108(2).

At step 608, the drilling management system 102 transmits the catch upresponse to the requesting client device 108(2). Again, the catch upmessage will be transmitted as a multicast and be received by allparticipating client devices 108, but will be ignored by each clientdevice other that the requesting client device 108(2) as identified bythe included unique identifier. The requesting client device 108(2) thenprocesses the catch up response, causing the requesting client device108(2) to render the visualization data of the drilling site accordingto the set of attributes defining the view state of the master clientdevice 108(1). As a result the view of the requesting client device108(2) will match that of the master client device 108(1). Upon beingadded to the shared visualization session, the requesting client device108(2) will be assigned as a slave, meaning that the requesting clientdevice 108(2) may be restricted from adjusting attributes for defining aview of the drilling site during the shared visualization session.Further, the view of the requesting client device 108(2), like all otherclient devices other than the master client device 108(1), will beadjusted according to changes made by the master client device 108(1).

FIG. 7 illustrates an example method 700 of synchronizing the view of amaster client device (e.g., the client device 108(1)) and a slave clientdevice (e.g., the client device 108(2)) in a shared visualizationsession. It should be understood that there can be additional, fewer, oralternative steps performed in similar or alternative orders, or inparallel, within the scope of the various embodiments unless otherwisestated.

At block 702, the drilling management system 102 receives, from a masterclient device 108(1), a view adjustment indicating that a user of themaster client device 108(1) has adjusted the set of attributes of thevisualization on the master client device 108(1). The view adjustmentmessage can include an updated set of attributes defining the new viewstate of the master client device 108(1).

At block 704, the drilling management system 102 transmits a viewadjustment command to each client device 108(2)-108(N) assigned as aslave. The view adjustment message can include the updated set ofattributes defining the new view state of the master client device108(1). The view adjustment message can be processed by each of theslave client devices 108(2)-108(N), causing each to render thevisualization data of the drilling site according to the updated set ofattributes defining the new view state of the master client device108(1).

While a slave client device is restricted from adjusting attributes fordefining a view of the drilling site during the shared visualizationsession, a slave client device can request to temporarily become themaster client device. FIG. 8 illustrates an example method 800 ofassigning a slave client device to be a temporary master client devicein a shared visualization session. It should be understood that therecan be additional, fewer, or alternative steps performed in similar oralternative orders, or in parallel, within the scope of the variousembodiments unless otherwise stated.

At block 802, a drilling management system 102 transmits, to a masterclient device 108(1), a temporary master status request indicating thata requesting client device (e.g., the client device 108(2)) hasrequested to become the master for the shared visualization session.

At block 804, the drilling management system receives, from the masterclient device 108(1), an authorization to approve the request of therequesting client device 108(2) to become the master for the sharedvisualization session. The authorization can include the uniqueidentifier for the requesting client device 108(2).

At block 806, the drilling management system 102 transmits theauthorization to the requesting client device 108(2). In certainimplementations, the authorization is transmitted as a multicast and isreceived by all participating client devices 108(2)-108(N), but will beignored by each client device other that the requesting client device108(2) as identified by the included unique identifier.

At block 808, the drilling management system 102 receives, from therequesting client device 108(2), an assuming temporary master statuscommand, which contains a set of updated attributes as well as theunique identifier of the requesting client device 108(2).

At block 810, the drilling management system 102 transmits the assumingtemporary master status commands to the other client devicesparticipating in the shared visualization session, including the masterclient device 108(1). This can cause the other client devices assignedas slaves and the master client device 108(1) to render thevisualization data of the drilling site according to the set of updatedattributes received from the requesting client device 108(2). Further,the other client devices can record the unique identifier of therequesting client device as being the temporary master.

When received by the master client device 108(1), the assuming temporarymaster status command can cause the master client device 108(1) to saveits current view state and render the visualization data of the drillingsite according to the set of updated attributes received from therequesting client device 108(2) that has been assigned temporary masterstatus.

Moving forward from this point, the requesting client device 108(2) isassigned as the temporary master and changes made to the view state ofthe temporary master client device 108(2) will be synchronized on theother client devices in the shared visualization session, including themaster client device 108(1).

After assigning the requesting client device 108(2) status as thetemporary master for the shared visualization session, the drillingmanagement system 102 may receive, from the client device 108(2), a viewadjustment indicating that a user of the client device 108(2) hasadjusted the view state of the client device 108(2) to yield a new setof attributes defining a second view of the drilling site. In responseto receiving the view adjustment, the drilling management system 102 maytransmit a view adjustment command to the other client devicesparticipating in the shared visualization session, including the masterclient device 108(1), causing the other client devices to render thevisualization data of the drilling site according to the new set ofattributes.

To revert back to control by the original master, the master clientdevice 108(1) may transmit a cancelling temporary master command or,alternatively, the temporary master client device 108(2) may transmit arelinquishing temporary master status command. In response to eithercommand, the temporary master client device 108(2) is reassigned as aslave for the shared visualization session and the status of the masterclient device 108(1) is restored. Accordingly, the slave client devicesagain recognize commands from the original master client device 108(1)and update their respective view states accordingly. In certainimplementations, the master client device 108(1) may also fullyrelinquish status as the master of the visualization session to thetemporary master client device 108(2) or another client deviceparticipating in the initiated visualization session.

In addition to facilitating shared visualization between the clientdevices 108, the drilling management system 102 may also enable users ofthe client devices 108 to share other resources including text, image,video, and other files. In certain implementations, for example, thedrilling management system 102 may include or otherwise have access to afile repository for use by members of an asset team. The drillingmanagement system 102 may then receive commands and corresponding datafrom the client devices 108 to create, access, delete, or otherwisemodify items in the repository. In some implementations, the repositorymay include a shared journal or similar log file by members of the assetteam to record and share information. Permissions for resources of therepository may vary, for example, certain members may only be grantedread access to certain resources while other members may be permitted toadd, delete, or otherwise modify the same resources.

Composite Wellbore Visualization

3D seismic viewing is particularly useful for geoscientists, who aretrained to and comfortable with thinking about the subsurface of theearth in three dimensions. In contrast, drilling engineers andtechnicians commonly work in two dimensions. Specifically, wells areconventionally drilled using a display called a “well vertical crosssection” (or “vertical section” for short), which is the establishedmeans for communication between drilling engineers and technicians. Inthe case of a horizontal well, the vertical section is a vertical crosssection of the earth starting at the surface location of the well thatruns along an azimuth (i.e., a clockwise rotation from either true ormagnetic North) that points at the proposed toe of the well. Onto thiscross section all the elements of the drilling project are provided,including the plan wellbore path, the actual wellbore path, and anyother relevant items.

In light of the differences in which geoscientists and engineers andtechnicians interpret and use data associated with a wellbore, systemsand methods in accordance with this disclosure facilitate generation andpresentation of drilling data that can be used to readily produce 3D and2D visualizations of a given wellbore. More specifically, plannedwellbore data and actual drilling data are combined to generatecomposite wellbore data. A 2D composite well vertical section may thenbe generated by projecting the composite wellbore data onto a verticalsection long a specified azimuth. In addition to the composite wellboredata, additional data, such as seismic data which may include geologicalfeatures or other points of interest may also be included in the 3D and2D visualizations. The 3D and 2D visualizations may also be selectivelydisplayed on a corresponding 3D or 2D referenced user interface, whichmay include color coding or other functions for facilitatingidentification and analysis of the drilling data. Accordingly,techniques for presenting drilling data described herein enable viewingof geoscientific data (e.g., geologic formation surfaces and geologicfault surfaces and seismic imagery) and engineering data (e.g., proposedand actual wellbores) in a flexible way that accommodates practices ofand enhanced collaboration between geoscientists, engineers, andtechnicians.

Data used in generating the previously described visualizations may becollected, stored, and accessed using a drilling management system, suchas the drilling management system 102 of FIGS. 1 and 2. Moreover, the 3Dand 2D visualizations may be presented to users of the drillingmanagement system 102 through respective client devices 108.Presentation of the 3D and 2D visualizations may occur in a sharedvisualization environment as previously described in the context ofFIGS. 5-8. For example, in certain implementations, visualizations maybe accessible to users of the client devices 108 through a browser-basedinterface, thereby enabling ready access to critical drillinginformation even in relatively remote operational conditions.

FIG. 9 is a surface view of a drilling plan 900 for a horizontal well902 that includes a vertical portion 903 and a horizontal portion 905(each shown in FIG. 10) between a well surface starting location 904(i.e., where drilling is initiated) and a toe 906 (i.e., where thehorizontal portion of the wellbore terminates). The drilling plan 900 isorganized based on a geographical North orientation and includes aplanned wellbore that defines the path a drill bit should take betweenthe well surface location 904 and the toe 906. During drilling, adrilling management system, such as the drilling management system 102of FIG. 1, receives captured drilling information, such as from an MWDtool incorporated into the drill string used to perform the drilling, asthe drill proceeds along the wellbore plan. As illustrated in FIG. 9, asolid line 908 is used to represent a portion of the actual drillingpath while a dashed line 910 represents a planned wellbore trajectory.As illustrated, the two lines may be coextensive or substantiallycoextensive such that the actual drilling path 908 tracks orapproximates the planned drilling path 910. Nevertheless, some deviationbetween the planned drilling path 910 and the actual drilling path 908may occur during the course of drilling operations.

FIG. 9 also includes a top view of a well vertical section 912 (notingthat the section is planar and has a depth along a z-axis perpendicularto the view shown in FIG. 9). More specifically, the well verticalsection 912 is a plane along the z-axis including each of the wellsurface starting location 904 and the toe 906. The well vertical section912 may be described by an azimuth angle (θ) 914 defined relative to aNorth projection 916 (which may be either true North or magnetic North)from the well surface starting location 904.

FIG. 10 is an isometric view of a map view of the drilling plan 900illustrated in FIG. 9. As shown in FIG. 10, the actual wellbore 908 andthe planned wellbore 910 define respective subsurface paths that includex-, y-, and z-components. A composite wellbore may generally be definedas a subsurface path including the actual wellbore 908 and any portionsof the planned wellbore 910 to be drilled. In general, the z-coordinatesreferred to herein may also be referred to as “true vertical depth” or“TVD” and are vertical distances below the well's datum (e.g., thesurface elevation or kelly bushing elevation).

As previously noted, the composite wellbore includes both plan andactual drilling information. For example, in some implementations, thecomposite wellbore may be generated by concatenating data correspondingto undrilled portions of the planned wellbore 910 with actual dataobtained during the drilling process representing the actual wellbore908. Notably, the actual drilling data on which the composite wellboreis based may be constantly changing as drilling of the well proceeds. Asa result, during a drilling operation, the composite wellbore may beconstantly refreshed to reflect any updated drilling informationreceived by systems according to the present disclosure.

To facilitate visualization of drilling information, systems and methodsin accordance with this disclosure use what are referred to herein asthree dimensional (“3D”) well cross sections. A 3D well cross section isa projection of a wellbore with x- and y-components such that the resultof the projection is a curved vertical plane. In contrast to the 3D wellcross sections, vertical sections are flat plane projection defined by acollection of xy-component and z-component pairings. Thus, the well 3Dsection is a curved cross section of the earth in three dimensions thatintersects a wellbore (composite or other) of a drilling well whereasthe well vertical section is a planar surface in two dimensions ontowhich the well 3D section is projected along a specified azimuth.

In FIG. 10, for example, a 3D well cross section 920 is defined alongthe composite wellbore. More specifically, the 3D well cross section 920is a curved plane resulting from the composite wellbore being projectedwith x- and y-components. FIG. 10 also includes a vertical section 912,which is a flat plane projection of the composite wellbore defined by acollection of xy-component and z-component pairings. FIG. 11 illustratesthe vertical section 912 of FIG. 10 in additional detail. As shown, thevertical section 912 includes a projection of information correspondingto the composite wellbore onto a vertical plane along a specifiedazimuth. Notably, any point on the wellbore path, such as point p (shownin FIG. 10), can be projected onto the vertical section. For example,the point p may be projected normal to the azimuth onto the verticalsection 912 to a point p′. Accordingly, the well vertical section mayinclude actual, planned, or composite wellbore information projected onthe well vertical section.

In addition actual, planned, and composite wellbore data, each of the 3Dwell cross section 920 and the vertical section 912 may also displayadditional features. For example, and without limitation, faultboundaries, formation information, property boundaries, and otherinformation, may also be projected onto either the 3D well cross section912 or the vertical section. Stated differently, geoscientific data,which may be comprised of geologic formation and fault surfaces, mayform intersections with the well 3D cross section 920. Suchintersections can then be projected onto the vertical section 912 withthe same techniques used to project the actual, planned, and/orcomposite wellbore data onto the vertical section 912.

The 3D well cross section 920 and the vertical section 912 may be storedas image data within a computing system, such as the drilling managementsystem 102 of FIG. 1, and later retrieved for visualization andanalysis. For example, the three dimensional well data may be stored asa 3D seismic image cube with the discrete points of well datarepresented as pixels of the 3D seismic image cube. Accordingly, the 3Dwell cross section 920 corresponds to a single pixel vertical plane thatmay be used to form a 2D image tracking the 3D well cross section 920.Each pixel of the 3D well cross section 920 can then be projected againonto a specific plane extending through the 3D seismic image cube tocreate an image of the vertical section 912. Accordingly, the 3D wellcross section 920 and the vertical section 912 may be readily displayedto members of an asset team or other users of the drilling managementsystem 102. Moreover, visualization of the 3D image cube may be readilychanged between 3D representations more commonly used by geoscientistsand 2D representations more commonly used by drilling engineers andtechnicians to facilitate communication between such parties.

FIG. 12 an example method 1200 of generating and displaying welldrilling information. It should be understood that there can beadditional, fewer, or alternative steps performed in similar oralternative orders, or in parallel, within the scope of the variousembodiments unless otherwise stated. Generally, the method 1200 includesthe process of generating and displaying a composite wellbore, such asthe composite wellbore 918 illustrated in FIGS. 9-11, and updating thedisplayed composite wellbore in response to receiving updated drillinginformation from an active drilling operation. The following discussionsof FIGS. 12-14 make additional reference to the system 100 and drillingmanagement system 102 of FIGS. 1 and 2. Such references are intendedonly to provide context to the following descriptions of the methodsillustrated in FIGS. 12-14.

At block 1202, planned wellbore data associated with a previouslycaptured three-dimensional seismic data set is accessed, such as by thedrilling management system 102. Such planned wellbore data may include,without limitation, three-dimensional points or similar geometricparameters defining the planned wellbore within a region of asubterranean formation for which three-dimensional seismic data has beenpreviously obtained.

At block 1204, the drilling management system 102 receives a drillingdata feed of actual drilling information for an actual wellboreassociated with the planned wellbore. For example, with reference toFIG. 1, the drilling management system 102 may receive data from one ormore of the drilling sites 106. Such data may be received and processedby the drilling management system 102 in real time during the course ofa drilling operation or may corresponding to a stored drilling feed fora previous drilling operation. The drilling data feed may be generated,for example, by an MWD or similar measurement device configured to trackand measure progress of a drilling operation. Similar to the plannedwellbore data, the drilling data feed may include, three-dimensionalpoints or similar geometric parameters defining the actual wellborewithin the region of the subterranean formation corresponding to thethree-dimensional seismic data.

At block 1206, the drilling management system 102 concatenates theactual drilling information with the planned wellbore data to form acomposite wellbore data set. The resulting composite wellbore data set,therefore, defines a composite wellbore that includes the actualwellbore that has been drilled with an undrilled portion of the plannedwellbore. In instances when the actual wellbore deviates from theplanned wellbore, concatenation of the actual wellbore and the plannedwellbore may include interpolating or otherwise inserting one or moredata points between the actual wellbore data and a portion of theplanned wellbore data such that the resulting composite wellbore dataset is continuous.

At block 1208, the drilling management system 102 generates welldrilling information including a three-dimensional well cross sectionintersecting the composite wellbore. As previously discussed in thecontext of FIGS. 9-11, the three-dimensional well cross section is acurved vertical plane that intersects the composite wellbore including arepresentation of the composite wellbore and that may further includeother geological and seismic data extending vertically from thecomposite wellbore.

At block 1210, the three-dimensional well cross section is displayed ona three-dimensionally reference user interface. For example, in certainimplementations, a client device, such as one of the client devices 108of FIG. 1, may be used to access the drilling management system 102, toretrieve the data corresponding to the three-dimensional well crosssection from the drilling management system 102, and to render the datain a three-dimensional user interface. In certain implementations, thedrilling management system 102 is accessed through a web browser orsimilar application and display of the data may occur in the context ofa shared visualization session, such as previously described in thisdisclosure.

At block 1212, additional drilling information is received from thedrilling data feed. For example, the drilling management system 102 mayreceive one or more updated data points corresponding to the actualdrilling path of a drilling operation performed at one of the drillingsites 106. In response to receiving the updated drilling information,the drilling management system 102 may update the previously generatedthree-dimensional well cross section to include the updated drillingdata. For example, the drilling management system 102 may repeat the oneor more of the operations of blocks 1202-1208 to generate an updatedcomposite wellbore that includes the recently received actual drillingdata.

At block 1214, the updated composite wellbore is displayed. To displaythe updated composite wellbore, the drilling management system 102 mayforward the updated composite wellbore data set to one or more of theclient devices 108 currently engaged in a visualization sessionincluding the composite wellbore. The client devices 108 may then renderthe updated composite wellbore data set accordingly to reflect changesto the actual and composite wellbore.

Displaying the composite wellbore may include displaying additional datastored within or otherwise available to the drilling management system102. For example, in certain implementations, image data included in the3D seismic data set may be projected onto the 3D well cross section anddisplayed along with the composite wellbore. Other data, such as thelocation of geological features, intersections between geologicalfeatures and the composite wellbore, and points of interest may also bedisplayed. In certain implementations, for example, a user of a clientdevice 108 may be able to add one or more feature points or similarpoints of interest to a visualization displayed on the user interfacewhich may then be shared with any other users that may be participatingin a shared visualization session with the user. Additional information,such as the distance and angle between identified feature points mayalso be computed and displayed.

FIG. 13 is an example method 1300 of displaying additional data of a 3Dseismic data set with a composite wellbore derived. It should beunderstood that there can be additional, fewer, or alternative stepsperformed in similar or alternative orders, or in parallel, within thescope of the various embodiments unless otherwise stated.

At block 1302, a geological feature is identified in the 3D seismic dataset. Such geological features may include, without limitation, one ormore of a pre-existing wellbore, a fault plane, and a lease boundary.Such features may be represented in the 3D seismic data set as one ormore points, lines, planes, or other geometric shapes within the 3Dseismic data.

At block 1304, an intersection between the geological feature and thecomposite wellbore data is computed. For example, the drillingmanagement system 102 may compare the points or geometric parameters ofthe composite wellbore to those of identified geological features of the3D seismic data set to identify points, lines, or planes along which thecomposite wellbore and the geological features intersect.

At block 1306, the intersection between the geological feature and thecomposite wellbore data is displayed on a three dimensionally referencedcomputer user interface, such as the three dimensionally referenced userinterface discussed in the context of the method 1200 of FIG. 12. Aspreviously discussed in the context of FIG. 12, the composite wellboreand 3D well cross section may be displayed on one or more client devices108 engaged in a visualization session. To the extent the drillingmanagement system 102 identifies an intersection between compositewellbore and a geological feature, such intersections may behighlighted, marked, or otherwise indicated in the data rendered by theclient devices 108 such that the intersections are rendered in a mannerthat increases their visibility. For example, the intersections may berendered by the client devices 108 in a different color, line thickness,line pattern, or other manner distinct from the rendering of thecomposite wellbore.

FIG. 14 is an example method 1400 of displaying drilling and wellinformation in a two dimensional representation. It should be understoodthat there can be additional, fewer, or alternative steps performed insimilar or alternative orders, or in parallel, within the scope of thevarious embodiments unless otherwise stated.

At block 1402, a well vertical section is generated subsequent to thegeneration of a composite wellbore as described in the context of themethod 1200 of FIG. 12. In certain implementations, for example, thedrilling management system 102 generates the well vertical section byidentifying an origin of a planned wellbore and extending a verticalplane from the planned wellbore origin along a specified azimuth. Thespecified azimuth may correspond to a default azimuth value, such as theazimuth defined by the origin and toe of the planned wellbore, or may bespecified by a user of a client device 108 in communication with thedrilling management system 102.

At block 1404, the composite wellbore is then projected onto the wellvertical section. In certain implementations, the composite wellbore maybe projected onto the well vertical section directly from 3D datarepresenting the composite wellbore. In other implementations, thecomposite wellbore may first be projected onto a 3D well cross sectionwhich is then projected onto the vertical section. Projection of thecomposite wellbore onto the vertical section may also include projectingadditional data onto the vertical section. Such data may include,without limitation, intersections between the composite wellbore andgeological features and image data, such as seismic image data. Thevertical section may also include feature points noted by users of thedrilling management system 102 and corresponding data, such as thedistances between feature points.

At block 1406, the well vertical section is then displayed to a userthrough a two dimensionally references user interface. For example,after projecting the composite wellbore and any additional drillinginformation onto the vertical section, the corresponding data may betransmitted by the drilling management system 102 to one or more of theclient devices 108 for rendering and display.

In certain implementations of the present disclosure, the user interfaceaccessible by the client devices 108 may include various additionalfeatures for readily viewing and analyzing wellbore and drillinginformation. For example, in certain implementations, the user interfacemay include a switch, button, or similar control through which a commandmay be received to switch between a three dimensionally referenced userinterface and a two dimensionally referenced user interface. In responseto such changes, the drilling management system 102 may transmitcorresponding 3D data (such as data corresponding to a 3D well crosssection) or 2D data (such as data corresponding to a vertical wellsection) to one or more client devices 108 that then render and displaythe received data.

FIG. 15A, and FIG. 15B illustrate exemplary possible system embodiments.The more appropriate embodiment will be apparent to those of ordinaryskill in the art when practicing the present technology. Persons ofordinary skill in the art will also readily appreciate that other systemembodiments are possible.

FIG. 15A illustrates a system bus computing system architecture 1500wherein the components of the system are in electrical communicationwith each other using a bus 1505. Exemplary system 1500 includes aprocessing unit (CPU or processor) 1510 and a system bus 1505 thatcouples various system components including the system memory 1515, suchas read only memory (ROM) 1520 and random access memory (RAM) 1525, tothe processor 1510. The system 1500 can include a cache of high-speedmemory connected directly with, in close proximity to, or integrated aspart of the processor 1510. The system 1500 can copy data from thememory 1515 and/or the storage device 1530 to the cache 1512 for quickaccess by the processor 1510. In this way, the cache can provide aperformance boost that avoids processor 1510 delays while waiting fordata. These and other modules can control or be configured to controlthe processor 1510 to perform various actions. Other system memory 1515may be available for use as well. The memory 1515 can include multipledifferent types of memory with different performance characteristics.The processor 1510 can include any general purpose processor and ahardware module or software module, such as module 1 1532, module 21534, and module 3 1536 stored in storage device 1530, configured tocontrol the processor 1510 as well as a special-purpose processor wheresoftware instructions are incorporated into the actual processor design.The processor 1510 may essentially be a completely self-containedcomputing system, containing multiple cores or processors, a bus, memorycontroller, cache, etc. A multi-core processor may be symmetric orasymmetric.

To enable user interaction with the computing device 1500, an inputdevice 1545 can represent any number of input mechanisms, such as amicrophone for speech, a touch-sensitive screen for gesture or graphicalinput, keyboard, mouse, motion input, speech and so forth. An outputdevice 1535 can also be one or more of a number of output mechanismsknown to those of skill in the art. In some instances, multimodalsystems can enable a user to provide multiple types of input tocommunicate with the computing device 1500. The communications interface1540 can generally govern and manage the user input and system output.There is no restriction on operating on any particular hardwarearrangement and therefore the basic features here may easily besubstituted for improved hardware or firmware arrangements as they aredeveloped.

Storage device 1530 is a non-volatile memory and can be a hard disk orother types of computer readable media which can store data that areaccessible by a computer, such as magnetic cassettes, flash memorycards, solid state memory devices, digital versatile disks, cartridges,random access memories (RAMs) 1525, read only memory (ROM) 1520, andhybrids thereof.

The storage device 1530 can include software modules 1532, 1534, 1536for controlling the processor 1510. Other hardware or software modulesare contemplated. The storage device 1530 can be connected to the systembus 1505. In one aspect, a hardware module that performs a particularfunction can include the software component stored in acomputer-readable medium in connection with the necessary hardwarecomponents, such as the processor 1510, bus 1505, display 1535, and soforth, to carry out the function.

FIG. 15B illustrates a computer system 1550 having a chipsetarchitecture that can be used in executing the described method andgenerating and displaying a graphical user interface (GUI). Computersystem 1550 is an example of computer hardware, software, and firmwarethat can be used to implement the disclosed technology. System 1550 caninclude a processor 1555, representative of any number of physicallyand/or logically distinct resources capable of executing software,firmware, and hardware configured to perform identified computations.Processor 1555 can communicate with a chipset 1560 that can controlinput to and output from processor 1555. In this example, chipset 1560outputs information to output 1565, such as a display, and can read andwrite information to storage device 1570, which can include magneticmedia, and solid state media, for example. Chipset 1560 can also readdata from and write data to RAM 1575. A bridge 1580 for interfacing witha variety of UI components 1585 can be provided for interfacing withchipset 1560. Such UI components 1585 can include a keyboard, amicrophone, touch detection and processing circuitry, a pointing device,such as a mouse, and so on. In general, inputs to system 1550 can comefrom any of a variety of sources, machine generated and/or humangenerated.

Chipset 1560 can also interface with one or more communicationinterfaces 1590 that can have different physical interfaces. Suchcommunication interfaces can include interfaces for wired and wirelesslocal area networks, for broadband wireless networks, as well aspersonal area networks. Some applications of the methods for generating,displaying, and using the GUI disclosed herein can include receivingordered datasets over the physical interface or be generated by themachine itself by processor 1555 analyzing data stored in storage 1570or 1575. Further, the machine can receive inputs from a user via UIcomponents 1585 and execute appropriate functions, such as browsingfunctions by interpreting these inputs using processor 1555.

It can be appreciated that exemplary systems 1500 and 1550 can have morethan one processor 1510 or be part of a group or cluster of computingdevices networked together to provide greater processing capability.

For clarity of explanation, in some instances the present technology maybe presented as including individual functional blocks includingfunctional blocks comprising devices, device components, steps orroutines in a method embodied in software, or combinations of hardwareand software.

In some embodiments the computer-readable storage devices, mediums, andmemories can include a cable or wireless signal containing a bit streamand the like. However, when mentioned, non-transitory computer-readablestorage media expressly exclude media such as energy, carrier signals,electromagnetic waves, and signals per se.

Methods according to the above-described examples can be implementedusing computer-executable instructions that are stored or otherwiseavailable from computer readable media. Such instructions can comprise,for example, instructions and data which cause or otherwise configure ageneral purpose computer, special purpose computer, or special purposeprocessing device to perform a certain function or group of functions.Portions of computer resources used can be accessible over a network.The computer executable instructions may be, for example, binaries,intermediate format instructions such as assembly language, firmware, orsource code. Examples of computer-readable media that may be used tostore instructions, information used, and/or information created duringmethods according to described examples include magnetic or opticaldisks, flash memory, USB devices provided with non-volatile memory,networked storage devices, and so on.

Devices implementing methods according to these disclosures can comprisehardware, firmware and/or software, and can take any of a variety ofform factors. Typical examples of such form factors include laptops,smart phones, small form factor personal computers, personal digitalassistants, and so on. Functionality described herein also can beembodied in peripherals or add-in cards. Such functionality can also beimplemented on a circuit board among different chips or differentprocesses executing in a single device, by way of further example.

The instructions, media for conveying such instructions, computingresources for executing them, and other structures for supporting suchcomputing resources are means for providing the functions described inthese disclosures.

Although a variety of examples and other information was used to explainaspects within the scope of the appended claims, no limitation of theclaims should be implied based on particular features or arrangements insuch examples, as one of ordinary skill would be able to use theseexamples to derive a wide variety of implementations. Further andalthough some subject matter may have been described in languagespecific to examples of structural features and/or method steps, it isto be understood that the subject matter defined in the appended claimsis not necessarily limited to these described features or acts. Forexample, such functionality can be distributed differently or performedin components other than those identified herein. Rather, the describedfeatures and steps are disclosed as examples of components of systemsand methods within the scope of the appended claims.

The invention claimed is:
 1. A method of generating well drillinginformation comprising: obtaining a planned wellbore data set for aplanned wellbore associated with a three-dimensional seismic data set,the planned wellbore data set including three-dimensional coordinatedata for a planned wellbore, wherein the three-dimensional coordinatedata for the planned wellbore defines a planned drilling path fixedprior to drilling an actual wellbore associated with the plannedwellbore; receiving a drilling data feed of actual wellbore data from adrilling site, the actual wellbore data including three-dimensionalcoordinate data corresponding to the actual wellbore associated with theplanned wellbore, wherein the three-dimensional coordinate datacorresponding to the actual wellbore describes an actual drilling path;generating a composite wellbore data set including three-dimensionalcoordinate data for a composite wellbore by concatenating thethree-dimensional coordinate data of the actual wellbore with a portionof the three-dimensional coordinate data of the planned wellbore datacorresponding to an undrilled portion of the planned wellbore such thatthe three-dimensional coordinate data for the composite wellbore definesa continuous drilling path including the actual drilling path as thedrilling data feed of the actual wellbore data is received and theportion of the planned drilling path corresponding to the undrilledportion of the planned wellbore; displaying a representation of thecomposite wellbore along the three-dimensional well cross section;modifying the composite wellbore data set according to the drilling datafeed; and updating the displayed composite wellbore based on themodified composite wellbore data set.
 2. The method of claim 1, whereingenerating the composite wellbore data set further comprisesinterpolating one or more three-dimensional coordinates between thethree-dimensional coordinate data of the actual wellbore and the portionof the three-dimensional coordinate data of the planned wellbore data.3. The method of claim 1 further comprising generating athree-dimensional well cross section intersecting the composite wellboreby projecting the three-dimensional coordinate data of the compositewell bore with x- and y-components onto a curved vertical plane.
 4. Themethod of claim 3 further comprising displaying the representation ofthe composite wellbore along the three-dimensional well cross section ona three dimensionally referenced user interface or a two dimensionallyreferenced user interface.
 5. The method of claim 4 further comprising:identifying a geological feature in the three-dimensional seismic dataset; computing an intersection between the geological feature and thecomposite wellbore, wherein computing an intersection between thegeological feature and the composite wellbore comprises identifying anoverlap between the three-dimensional coordinate data defining thecomposite wellbore and the three-dimensional seismic data correspondingto the geological feature; and displaying, on the three dimensionallyreferenced user interface, the intersection between the geologicalfeature and the composite wellbore.
 6. The method of claim 4 furthercomprising: generating, from the three-dimensional seismic data, imagedata for a formation along the three-dimensional well cross section; anddisplaying, on the three dimensionally referenced user interface, theimage data on the three-dimensional well cross section.
 7. The method ofclaim 4 further comprising: modifying the composite wellbore data setaccording to the drilling data feed during a drilling operation;regenerating at least a portion of the composite wellbore data set toyield an updated composite wellbore data set; generating an updatedthree-dimensional well cross section based on the updated compositewellbore data set; and displaying the updated three-dimensional wellcross section on the three dimensionally referenced user interface. 8.The method of claim 3 further comprising generating a well verticalsection from a well origin of the planned wellbore along a specifiedazimuth, wherein generating the well vertical section comprisesprojecting the composite wellbore data set onto a flat vertical planeextending from the well origin along the specified azimuth.
 9. Themethod of claim 8 further comprising projecting at least one of anintersection between a geological feature and the composite wellbore andimage data for a formation along the three-dimensional well crosssection onto the well vertical section.
 10. The method of claim 8further comprising displaying the well vertical section on a twodimensionally referenced user interface.
 11. The method of claim 8further comprising switching, in response to a command received from auser, between displaying the well vertical section using a twodimensionally referenced user interface and the three-dimensional wellcross section using a three dimensionally referenced user interface. 12.The method of claim 1 further comprising color coding the actualwellbore data and planned wellbore data aspects of the compositewellbore for display on at least one of a three dimensionally referenceduser interface and a two dimensionally referenced user interface. 13.The method of claim 1 further comprising: receiving selections of afirst feature point displayed on a three dimensionally referenced userinterface and a second feature point displayed on the threedimensionally referenced user interface; projecting the first featurepoint and the second feature point on a vertical well section, whereinthe vertical well section is a flat vertical plane extending from a wellorigin of the planned wellbore data along a specified azimuth; anddisplaying the first feature point and the second feature point in a twodimensionally referenced user interface.
 14. The method of claim 13further comprising computing a distance between the first feature pointand the second feature point as projected on the vertical well section.15. A drilling management system comprising: one or more computerprocessors; and a memory storing instructions that, when executed by theone or more computer processors, cause the drilling management systemto: obtain a planned wellbore data set for a planned wellbore associatedwith a three-dimensional seismic data set, the planned wellbore data setincluding three-dimensional coordinate data for a planned wellbore,wherein the three-dimensional coordinate data for the planned wellboredefines a planned drilling path fixed prior to drilling an actualwellbore associated with the planned wellbore; receive a drilling datafeed of actual wellbore data from a drilling site, the actual wellboredata including three-dimensional coordinate data corresponding to anactual wellbore associated with the planned wellbore, wherein thethree-dimensional coordinate data corresponding to the actual wellboredescribes an actual drilling path; generate a composite wellbore dataset including three-dimensional coordinate data for a composite wellboreby concatenating the three-dimensional coordinate data of the actualwellbore with a portion of the three-dimensional coordinate data of theplanned wellbore data corresponding to an undrilled portion of theplanned wellbore such that the three-dimensional coordinate data for thecomposite wellbore defines a continuous drilling path including theactual drilling path as the drilling data feed of the actual wellboredata is received and the portion of the planned drilling pathcorresponding to the undrilled portion of the planned wellbore; displaya representation of the composite wellbore along the three-dimensionalwell cross section; modify the composite wellbore data set according tothe drilling data feed; and update the displayed composite wellborebased on the modified composite wellbore data set.
 16. The drillingmanagement system of claim 15, wherein the instructions further causethe drilling management system to generate the composite wellbore dataset by interpolating one or more three-dimensional coordinates betweenthe three-dimensional coordinate data of the actual wellbore and theportion of the three-dimensional coordinate data of the planned wellboredata.
 17. The drilling management system of claim 15, wherein theinstructions further cause the drilling management system to generate athree-dimensional well cross section intersecting the composite wellboreby projecting the three-dimensional coordinate data of the compositewell bore with x- and y-components onto a curved vertical plane.
 18. Thedrilling management system of claim 17, wherein the instructions furthercause the drilling management system to display a representation of thecomposite wellbore along the three-dimensional well cross section on athree dimensionally referenced user interface or a two dimensionallyreferenced user interface.
 19. The drilling management system of claim18, wherein the instructions further cause the drilling managementsystem to: identify a geological feature in the three-dimensionalseismic data set; compute an intersection between the geological featureand the composite wellbore, wherein computing an intersection betweenthe geological feature and the composite wellbore comprises identifyingan overlap between the three-dimensional coordinate data defining thecomposite wellbore and the three-dimensional seismic data correspondingto the geological feature; and display, on the three dimensionallyreferenced user interface, the intersection between the geologicalfeature and the composite wellbore.
 20. The drilling management systemof claim 18, wherein the instructions further cause the drillingmanagement system to: generate, from the three-dimensional seismic data,image data for a formation along the three-dimensional well crosssection; and display, on the three dimensionally referenced userinterface, the image data on the three-dimensional well cross section.21. The drilling management system of claim 18, wherein the instructionsfurther cause the drilling management system to: modify the compositewellbore data set according to the drilling data feed during a drillingoperation; regenerate at least a portion of the composite wellbore dataset to yield an updated composite wellbore data set; generate an updatedthree-dimensional well cross section based on the updated compositewellbore data set; and display the updated three-dimensional well crosssection on the three dimensionally referenced user interface.
 22. Thedrilling management system of claim 17, wherein the instructions furthercause the drilling management system to generate a well vertical sectionfrom a well origin of the planned wellbore along a specified azimuth,wherein generating the well vertical section comprises projecting thecomposite wellbore data set onto a flat vertical plane extending fromthe well origin along the specified azimuth.
 23. The drilling managementsystem of claim 22, wherein the instructions further cause the drillingmanagement system to project at least one of an intersection between ageological feature and the composite wellbore and image data for aformation along the three-dimensional well cross section onto the wellvertical section.
 24. The drilling management system of claim 22,wherein the instructions further cause the drilling management system todisplay the well vertical section on a two dimensionally referenced userinterface.
 25. The drilling management system of claim 22, wherein theinstructions further cause the drilling management system to switch, inresponse to a command received from a user, between displaying the wellvertical section using a two dimensionally referenced user interface andthe three-dimensional well cross section using a three dimensionallyreferenced user interface.
 26. The drilling management system of claim25, wherein the instructions further cause the drilling managementsystem to color code the actual wellbore data and planned wellbore dataaspects of the composite wellbore for display on at least one of a threedimensionally referenced user interface and a two dimensionallyreferenced user interface.
 27. The drilling management system of claim25, wherein the instructions further cause the drilling managementsystem to: receive selections of a first feature point displayed on athree dimensionally referenced user interface and a second feature pointdisplayed on the three dimensionally referenced user interface; projectthe first feature point and the second feature point on a vertical wellsection, wherein the vertical well section is a flat vertical planeextending from a well origin of the planned wellbore data along aspecified azimuth; and display the first feature point and the secondfeature point in a two dimensionally referenced user interface.
 28. Thedrilling management system of claim 27, wherein the instructions furthercause the drilling management system to compute a distance between thefirst feature point and the second feature point as projected on thevertical well section.